WATCH ABOVE: More than 60,000 people in Alberta's oil and gas industry lost their jobs during the latest downturn. Things are turning around and some are slowly headed back to work. But as Quinn Ohler reports, the jobs are not what they once were.

Imperial Oil Ltd.’s commitment to begin construction this year on its $2.6-billion Aspen oilsands project in northern Alberta comes less than a week after it received long-awaited approval from the Alberta government.

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The speed of the announcement Tuesday surprised observers who have watched Calgary oilsands rivals including Canadian Natural Resources Ltd., Cenovus Energy Inc. and MEG Energy Corp. announce production cuts to avoid steep discounts currently being paid for Western Canadian Select bitumen blend.

Imperial’s project would add 75,000 barrels per day of bitumen production to current output of about 300,000 bpd but won’t start up until 2022, by which time many analysts predict that new pipelines will ease export bottlenecks and restore normal pricing levels.

On a webcast from Imperial’s investor day in Toronto on Wednesday morning, CEO Rich Kruger said the company’s focus is on in situ oilsands projects which produce bitumen from wells, instead of open pit mines such as its Kearl project that opened in 2013 and was expanded in 2015.

“Where does Canada fit in? Our view is with the large resource base, with the history of innovation and responsible development, that the highest quality oilsands can and will be competitive on a global basis, not all oilsands,” he said.

“We see in situ as having fundamental advantages today over new greenfield mining developments.”

Imperial decided to go ahead with construction during a slow time in the oilsands because it hopes less competition will save money on labour and component costs, said Theresa Redburn, senior vice-president of commercial and corporate development.

The project is being designed to add solvents along with steam into horizontal wells to melt the heavy sticky bitumen, a technology tested in a seven-year pilot project, Redburn said.

Imperial expects to save about 25 per cent in capital costs per barrel and reduce greenhouse gas emissions and water use intensity by about the same amount compared with traditional in situ projects that use steam alone.

In a report, analysts at Tudor Pickering & Holt questioned the project’s cost of about $35,000 per barrel per day versus previous company estimates that the entire 150,000-bpd project could be built for $27,000 per flowing barrel.

It said the cash-rich company can afford to ramp up spending next year and still buy back $2 billion worth of its shares.

The project’s approval process has been a bone of contention with Kruger, who has complained it was taking too long to win approval from the Alberta Energy Regulator since application was first made in 2013.

The AER, however, says the review period was prolonged due to changes to Imperial’s application, with the latest version submitted in May 2017, and First Nation consultation adequacy requirements.

The Aspen project is expected to create about 700 jobs during peak construction and more than 200 jobs during operations.

Enbridge Inc.’s Line 3 replacement oil pipeline project is expected to be in service in late 2019 and one or both of TransCanada Corp.’s Keystone XL pipeline or the federal government’s Trans Mountain expansion are expected to be in service a year or so later.

Meanwhile, crude-by-rail exports from Canada rose to a record 230,000 barrels per day in August. Imperial has signalled it will increase rail use to 170,000 bpd in the first quarter of 2019, up from an average of about 80,000 bpd over the summer.